For many years seismic exploration for oil and gas has involved the use of a source of seismic energy and its reception by an array of seismic detectors, generally referred to as geophones. When used on land, the source of seismic energy can be a high explosive charge electrically detonated in a borehole located at a selected point on a terrain, or another energy source having capacity for delivering a series of impacts or mechanical vibrations to the earth's surface. Offshore, airgun sources and hydrophones are commonly used. The acoustic waves generated in the earth by these sources are transmitted back from strata boundaries and/or other discontinuities and reach the surface at varying intervals of time, depending on the distance traversed and the characteristics of the subsurface traversed. On land these returning waves are detected by the geophones, which finction to transduce such acoustic waves into representative electrical analog signals. In use an array of geophones is generally laid out along a line to form a series of observation stations within a desired locality, the source injects acoustic signals into the earth, and the detected signals are recorded for later processing using digital computers, where the analog data is generally quantized as digital sample points, e.g., one sample every two milliseconds, such that each sample point may be operated on individually. Accordingly, continuously recorded seismic field traces are reduced to vertical cross sections of the earth, which approximate subsurface structure. The geophone array is then moved along the line to a new position and the process repeated to provide a seismic survey. Seismic data processing techniques such as migration of reflections, which permit the geological structure of subsurface to be accurately determined, are well known to those skilled in the art.
More recently, seismic surveys involve geophones and sources laid out in generally rectangular grids covering an area of interest so as to survey a large area, and enable construction of three dimensional (3D) views of reflector positions over wide areas. A major advantage of 3D technology is in allowing seismic data to be displayed in horizontal or "map" format. While faults are readily seen on vertical cross sections, many adjacent sections must be examined to determine the lateral extent of faulting. A horizon slice which illustrates a generally horizontal surface cut through the 3D seismic data volume can show the lateral extent of the fault as well as the stratigraphic features of horizons.
As explorationists seek new areas in which to find hydrocarbons, many of the new areas under exploration contain complex geological structures, and rapid analysis of seismic data for interpreting structure in these areas is a distinct advantage. Common subterranean structures that provide geologists with more detailed understanding of reservoirs include stratigraphic horizons and faults. As used herein, a horizon is a surface separating two different rock layers that is associated with a seismic reflector, and which reflector can be detected over a large area. A fault, which is likewise associated with a disruption or offset of seismic reflectors, is a displacement of rocks along a shear surface.
Stratigraphic interpretation identifying horizons and/or faults on a seismic section is accomplished by a technique known as "picking" where a common seismic trace attribute, such as trace amplitude, is selected for tracking across a vertical cross section or horizontal slice seismic record to track the reflector. Manual picking of seismic attributes for visualizing stratigraphic and fault information from seismic amplitude by drawing with colored pencil on paper or with a cursor on an interactive computer screen, as practiced in the past, can be complex, tedious and imprecise. And creating a consistent geological interpretation from large 3D seismic data volumes often requires separate, time-consuming interpretations of both faulting and stratigraphy. These interpretations must then be integrated into a single, final interpretation.
Automating the seismic attribute picking process has been pursued in the seismic industry for some time, however, no fully satisfactory automated method has been achieved. This is because no one scheme of numerical enhancements to the picking process is universally applicable to all seismic data, or even applicable within different sections of the same 3D data volume.
Accordingly, it is an object of this invention to more universally, consistently and accurately identify faults in seismic sections compared to current manual or semi-automated techniques.
A more specific object of this invention is to provide a method for automatic fault picking of up to 99% of seismically detectable faults in 3D seismic subvolumes.
Another object is to create a 3D fault plane data volume that facilitates fault analysis and accelerates by at least two fold a fault analysis using conventional picking methods.
Yet another object is to create a data volume that better displays faults in 3D animation and in rendered visualization on computer workstations.
Still another object is to provide a technique in which conventional seismic data is merged and displayed in combination with fault enhanced data.
Another object is to provide a method for which stratigraphically enhanced seismic data or geological property enhanced data is merged and displayed in combination with fault enhanced data.
Still another object is to automatically pick fault planes on multiple seismic lines so as to eliminate a major portion of the manual picking process.
A still more specific object is to detect faults having minimal offsets.